The treatment of subterranean formations penetrated by a well bore to stimulate the production of hydrocarbons therefrom or the ability of the formation to accept injected fluids has long been known in the art. One of the most common methods of increasing productivity of a hydrocarbon-bearing formation is to subject the formation to a fracturing treatment. This treatment is effected by injecting a liquid, gas or two-phase fluid, generally referred to as a fracturing fluid, down the well bore at sufficient pressure and flow rate to fracture the subterranean formation. A proppant material such as sand, fine gravel, sintered bauxite, glass beads or the like can be introduced into the fracture to prop the fracture open once the treatment has stopped. The propped fracture provides larger flow channels through which an increased quantity of a hydrocarbon can flow, thereby increasing the productive capability of a well.
Traditional fracturing techniques utilize water or oil-based fluids to fracture a hydrocarbon-bearing formation. Recently, fracturing techniques utilizing fluids comprising carbon dioxide and/or nitrogen have been developed. U.S. Pat. No. Re 32,302, by Almond et al., discusses a method of fracturing a subterranean formation with a stabilized foamed fracturing fluid comprising from about 50 percent to in excess of about 96 percent by volume of carbon dioxide with the remainder comprising an aqueous liquid and a selected surfactant. A foam is formed in situ by injection of a stabilized liquid-liquid emulsion containing liquid carbon dioxide into a well bore penetrating the formation. The temperature and pressure of the emulsion is controlled to maintain the carbon dioxide in the liquid phase during injection into the well bore. Thereafter, the carbon dioxide is heated by the subterranean formation to a temperature above about 88° F. at which time the stabilized emulsion spontaneously forms a stabilized foam.
U.S. Pat. No. 5,069,283, by Mack, describes a hydraulic fracturing process in which substantial quantities of both nitrogen and carbon dioxide are incorporated into the fracturing fluid. Nitrogen and carbon dioxide are separately incorporated into an aqueous based fracturing fluid in amounts to provide a volume ratio of nitrogen to carbon dioxide at wellhead conditions within the range of about 0.2–1.0. The volume ratio of the total of carbon dioxide and nitrogen to the aqueous phase of the aqueous fracturing fluid at wellhead conditions is within the range of about 1–4. The aqueous fracturing fluid containing the nitrogen and carbon dioxide is injected in the well under a pressure sufficient to implement hydraulic fracturing of the subterranean formation undergoing treatment. A thickening agent may be incorporated into water to provide a viscous aqueous based fracturing fluid to which the carbon dioxide and nitrogen are added. The carbon dioxide is incorporated in liquid phase and the nitrogen in gaseous phase. Propping agent is incorporated into at least a portion of the fracturing fluid. Addition of the propping agent takes place prior to addition of the carbon dioxide and nitrogen.
U.S. Pat. No. 5,566,760, by Harris, describes an aqueous foamed fracturing fluid composition and method for using the foamed fracturing fluid for fracturing subterranean formations wherein the foamed fracturing fluid comprises: (a) a viscosifier that is preferably either hydrophobically modified guar or hydrophobically modified hydroxymethylcellulose; (b) a surfactant that is preferably alpha olefin sulfonate; and (c) a gas phase that includes either nitrogen or carbon dioxide.
A deficiency in the present state of the art is that it is difficult to remove foamed fluids from the formation and from the well bore. One problem is that the foamed fluid tends to carry proppant material back out of the formation as the fluid is removed from the formation. The foamed fluid also causes problems in the flow-back tanks used to contain the recovered fluid. It is therefore common to use “breakers” to attempt to destroy the foam before recovering the fracturing fluid. Problems exist with using breakers, however. For example, breaker fluids themselves contain chemical emulsifiers, which have foaming tendencies. Therefore, a need exists in the art for methods of “breaking” foamed fracturing fluids so that they can be recovered from subterranean formations and well bores.